Method for flow profiling using active-source heating or cooling and temperature profiling

ABSTRACT

A method and apparatus are provided for determining movement of a fluid into or out of a subsurface wellbore, to thereby enable accurate allocation of fluids being produced by or injected into each of several zones of the wellbore. A temperature change is effected in the fluid at a first location in the wellbore. A temperature of the fluid is measured at one or more sensing locations downstream of the location of the temperature change. A simulated heat flow profile is generated from a wellbore model. The simulated heat flow profile is compared to the measured temperature of the fluid at the one or more sensing locations. An inversion model is used to determine, for a plurality of points of interest, a fluid flow direction and/or a cumulative flow rate contribution.

CROSS REFERENCE TO RELATED APPLICATIONS

This application claims the priority benefit of U.S. ProvisionalApplication No. 62/635,265, filed Feb. 26, 2018 entitled “Method forFlow Profiling Using Active-Source Heating or Cooling and TemperatureProfiling,” the entirety of which is incorporated herein.

FIELD

The present disclosure relates generally to drilling for hydrocarbons.More specifically, the present disclosure relates to determining flowprofiles in a wellbore.

BACKGROUND

In the oil and gas industry, it is desirable to obtain flow data from awellbore. It is more particularly desirable to determine the locationsand flow rates of various inflows into a wellbore. The practice ofdetermining the locations and flow rates of various inflow zones in asubsurface formation is known as zonal allocation. Cumulative flowprofiling along the length of a wellbore has traditionally been doneusing mechanical spinner surveys. Often a temperature log is used incombination with the spinner, which is sometimes unduly influenced bythe presence of gas or wellbore geometry in the case of multi-phaseflows.

Recently the use of standalone temperature logging via permanentlyinstalled distributed temperature sensing (DTS) systems have beensuccessfully used for zonal allocations in both deviated and verticalwells. DTS is a technique of monitoring temperature along the length ofa wellbore using an optical waveguide, such as an optical fiber, as atemperature sensor. In a typical DTS system, a laser or other lightsource at the surface of the well transmits a pulse of light into afiber optic cable installed along the length of a well. Due tointeractions with molecular vibrations within the glass of the fiber, aportion of the light is scattered back towards the surface (thisphenomenon is referred to as Raman scattering and/or Rayleighscattering, but will be generically referred to herein as “scattering”).FIG. 1 illustrates a conventional DTS system 100 for measuring thetemperature in a wellbore 110. A transmitter 102 irradiates a waveguide120 with light signals (pump radiation) capable of causing scattering. Acoupler 104 includes suitable optical elements to guide pump radiationdown the waveguide 120 and guide backscattered light signals to areceiver 106. The receiver 106 translates the backscattered lightsignals into electrical signals that are fed to a processor 108 capableof generating a distributed temperature profile therefrom. The graph 200shown in FIG. 2 illustrates a waveform 202 across a spectrum ofbackscattered light signals generated by the pump radiation. Asillustrated, the backscattered signals include smaller amplitude signalsin the Stokes and anti-Stokes bands. The Stokes and anti-Stokes signalsare typically processed by the processor 108 at the surface to calculatea ratio of power between upper and lower frequency bands of detectedsignals. There is a known temperature dependence of this ratio, whichallows for convenient temperature sensing based on the detected lightsignals scattered to the surface. The anti-Stokes signal is sensitive totemperature changes, which result in changes in amplitude of theanti-Stokes signal (as illustrated by the dashed line 204), while theStokes signal is insensitive to temperature. Because speed of light inthe waveguide 120 is known, it is possible to determine positions alongthe fiber at which scattering occurred, based on the time of arrival ofthe backscattered light signals. Hence, the DTS system is capable ofmeasuring temperature as a continuous function of position over a lengthof the fiber, which may be correlated to a depth of the wellbore.

Most zonal allocation workflows using temperature data rely on thedifference between the fluid temperature entering the wellbore from thereservoir at each depth and the (typically warmer) fluid temperature ofthe fluid already in the wellbore flowing from deeper in the well. Bycalculating the expected heat loss as the fluid travels up the well, theexpected temperature due to mixing of the fluids entering the wellbore,and the impact of any Joule-Thomson heating/cooling of the fluids asthey change pressure, it is possible to use detailed temperaturemeasurements to model the zonal inflows along the wellbore. However,this difference in fluid entry temperature along the length of thewellbore is generally very small in highly deviated or horizontal wells.For these wells a different technique is required which does not rely onthe natural geothermal temperature gradient.

Additionally, the traditional conveyance of the spinner or temperaturelogging device has been via wireline/cable in vertical wells and viacoiled tubing in deviated wells. With increasing length of thehorizontal portion of the wellbore, larger diameter coiled tubing mustbe employed to reach the end of the well. As the measuring device takesup a larger portion of the cross-section, the flow inside the wellboreis increasingly altered by the presence of the device.

U.S. Pat. No. 9,557,437 to Selker, et al. discloses a geohydrologymonitoring system that uses a heating mechanism to heat water in a well.The heating mechanism comprises an array of heating elements that heatwater in a well. A DTS system measures the temperature of the water andinfers flow information from the temperature measurements. Thegeohydrology monitoring system described in the '437 patent has a fewexpected shortcomings, however, when applied to oil and gas productionor water/hydrocarbon injection wells: First, the flow rates in suchwells are significantly higher than those encountered in geohydrologicmonitoring. This means that the temperature spikes caused by an arrayheater interfere with or “smear” into one another, making it verydifficult to use a numerical model to clearly define zonal allocation.Second, there are significant challenges in installing and/or deployingan array heater, which is a critical consideration in long horizontaland particularly in unconventional hydrocarbon wells. Specifically,installation outside the casing is typically a problem, since casingrunning may be mechanically aggressive and require rotation, jarring,and reciprocation of the casing string to reach total depth. Also, theextra time of clamping the assembly to the outside of casing jointsnormally may add an unacceptable amount of rig time and cost to thedrilling operation. Installation of the heating array inside the casingand directly in contact with the production or injection fluids is alsonot desirable as there is often debris which flows and will either stickto the array tool or obstruct the well during operation, so the need fora clear casing inside diameter is key and the ability to mechanicallyclean out any debris is required. This is normally addressed in thepetroleum industry by running tools on coiled tubing, rods or tractoredwireline in long horizontal wells that are specially designed to have aminimum diameter and specially tapered to move through debris in thecasing.

The third shortcoming of the '437 patent is that the operatingenvironment in hydrocarbon wells is simply non-analogous to what isexperienced in the geohydrologic monitoring field. For example,temperatures in excess of 300 degrees Fahrenheit and pressures ofseveral thousand psi are not unusual in a hydrocarbon well, and thefluids encountered are often severely corrosive. Electronics andmetallic components need to be specially designed to handle theseaggressive conditions, and such design considerations are neitherconsidered nor suggested by the '437 patent. What is needed is a methodof obtaining temperature measurements in a wellbore (and specifically, ahorizontal wellbore or a highly deviated wellbore) that does not requirea mechanical spinner array—which requires the use of a wireline tractoror large diameter tubing—and provides some other source of temperaturechange inside the wellbore to estimate flow-rates, since fluid entrytemperature is fairly uniform along the wellbore.

SUMMARY

In one aspect, a method is provided for determining movement of a fluidinto or out of a subsurface wellbore. This method enables accurateallocation of fluids being produced by or injected into each of severalzones of the wellbore. A temperature change is effected in the fluid ata first location in the wellbore. A temperature of the fluid is measuredat one or more sensing locations downstream of the location of thetemperature change. A change in temperature between the first locationand each of the one or more sensing locations is representative of heatflow within the wellbore. A simulated heat flow profile is generatedfrom a wellbore model. The simulated heat flow profile is compared tothe measured temperature of the fluid at the one or more sensinglocations. An inversion model is used to determine, for a plurality ofpoints of interest, a fluid flow direction and/or a cumulative flow ratecontribution.

In another aspect, a system for determining movement of a fluid into orout of a subsurface wellbore is provided, to thereby enable accurateallocation of fluids being produced by or injected into each of severalzones of the well. Means are provided for effecting a temperature changein the fluid at a first location in the wellbore. Means are provided formeasuring a temperature of the fluid at one or more sensing locationsdownstream of the location of the temperature change. A change intemperature between the first location and each of the one or moresensing locations is representative of heat flow within the wellbore.Means are provided for generating a simulated heat flow profile from awellbore model. Means are provided for comparing the simulated heat flowprofile to the measured temperature of the fluid at the one or moresensing locations. Means are provided for using an inversion model todetermine, for a plurality of points of interest, a fluid flow directionand/or a cumulative flow rate contribution.

DESCRIPTION OF THE DRAWINGS

The present disclosure is susceptible to various modifications andalternative forms, specific exemplary implementations thereof have beenshown in the drawings and are herein described in detail. It should beunderstood, however, that the description herein of specific exemplaryimplementations is not intended to limit the disclosure to theparticular forms disclosed herein. This disclosure is to cover allmodifications and equivalents as defined by the appended claims. Itshould also be understood that the drawings are not necessarily toscale, emphasis instead being placed upon clearly illustratingprinciples of exemplary embodiments of the present invention. Moreover,certain dimensions may be exaggerated to help visually convey suchprinciples. Further where considered appropriate, reference numerals maybe repeated among the drawings to indicate corresponding or analogouselements. Moreover, two or more blocks or elements depicted as distinctor separate in the drawings may be combined into a single functionalblock or element. Similarly, a single block or element illustrated inthe drawings may be implemented as multiple steps or by multipleelements in cooperation. The forms disclosed herein are illustrated byway of example, and not by way of limitation, in the figures of theaccompanying drawings and in which like reference numerals refer tosimilar elements and in which:

FIG. 1 is a schematic diagram of a known DTS system;

FIG. 2 is a graph showing a waveform generated by the DTS system of FIG.1;

FIG. 3 is a schematic diagram of a temperature measurement systemaccording to disclosed aspects;

FIGS. 4A and 4B are graphs showing temperature read-outs as a functionof depth using the temperature measurement system according to disclosedaspects:

FIG. 4C is a graph showing predicted inflows to a hydrocarbon wellaccording to disclosed aspects; and

FIG. 5 is a flowchart of a method of determining movement of a fluidinto or out of a subsurface wellbore according to disclosed aspects.

DETAILED DESCRIPTION Terminology

The words and phrases used herein should be understood and interpretedto have a meaning consistent with the understanding of those words andphrases by those skilled in the relevant art. No special definition of aterm or phrase, i.e., a definition that is different from the ordinaryand customary meaning as understood by those skilled in the art, isintended to be implied by consistent usage of the term or phrase herein.To the extent that a term or phrase is intended to have a specialmeaning, i.e., a meaning other than the broadest meaning understood byskilled artisans, such a special or clarifying definition will beexpressly set forth in the specification in a definitional manner thatprovides the special or clarifying definition for the term or phrase.

For example, the following discussion contains a non-exhaustive list ofdefinitions of several specific terms used in this disclosure (otherterms may be defined or clarified in a definitional manner elsewhereherein). These definitions are intended to clarify the meanings of theterms used herein. It is believed that the terms are used in a mannerconsistent with their ordinary meaning, but the definitions arenonetheless specified here for clarity.

A/an: The articles “a” and “an” as used herein mean one or more whenapplied to any feature in embodiments and implementations of the presentinvention described in the specification and claims. The use of “a” and“an” does not limit the meaning to a single feature unless such a limitis specifically stated. The term “a” or “an” entity refers to one ormore of that entity. As such, the terms “a” (or “an”), “one or more” and“at least one” can be used interchangeably herein.

About: As used herein, “about” refers to a degree of deviation based onexperimental error typical for the particular property identified. Thelatitude provided the term “about” will depend on the specific contextand particular property and can be readily discerned by those skilled inthe art. The term “about” is not intended to either expand or limit thedegree of equivalents which may otherwise be afforded a particularvalue. Further, unless otherwise stated, the term “about” shallexpressly include “exactly,” consistent with the discussion belowregarding ranges and numerical data.

Above/below: In the following description of the representativeembodiments of the invention, directional terms, such as “above”,“below”, “upper”, “lower”, etc., are used for convenience in referringto the accompanying drawings. In general, “above”, “upper”, “upward” andsimilar terms refer to a direction toward the earth's surface along awellbore, and “below”, “lower”, “downward” and similar terms refer to adirection away from the earth's surface along the wellbore. Continuingwith the example of relative directions in a wellbore, “upper” and“lower” may also refer to relative positions along the longitudinaldimension of a wellbore rather than relative to the surface, such as indescribing both vertical and horizontal wells.

And/or: The term “and/or” placed between a first entity and a secondentity means one of (1) the first entity, (2) the second entity, and (3)the first entity and the second entity. Multiple elements listed with“and/or” should be construed in the same fashion, i.e., “one or more” ofthe elements so conjoined. Other elements may optionally be presentother than the elements specifically identified by the “and/or” clause,whether related or unrelated to those elements specifically identified.Thus, as a non-limiting example, a reference to “A and/or B”, when usedin conjunction with open-ended language such as “comprising” can refer,in one embodiment, to A only (optionally including elements other thanB); in another embodiment, to B only (optionally including elementsother than A); in yet another embodiment, to both A and B (optionallyincluding other elements). As used herein in the specification and inthe claims, “or” should be understood to have the same meaning as“and/or” as defined above. For example, when separating items in a list,“or” or “and/or” shall be interpreted as being inclusive, i.e., theinclusion of at least one, but also including more than one, of a numberor list of elements, and, optionally, additional unlisted items. Onlyterms clearly indicated to the contrary, such as “only one of” or“exactly one of,” or, when used in the claims, “consisting of,” willrefer to the inclusion of exactly one element of a number or list ofelements. In general, the term “or” as used herein shall only beinterpreted as indicating exclusive alternatives (i.e., “one or theother but not both”) when preceded by terms of exclusivity, such as“either,” “one of,” “only one of,” or “exactly one of”.

Any: The adjective “any” means one, some, or all indiscriminately ofwhatever quantity.

At least: As used herein in the specification and in the claims, thephrase “at least one,” in reference to a list of one or more elements,should be understood to mean at least one element selected from any oneor more of the elements in the list of elements, but not necessarilyincluding at least one of each and every element specifically listedwithin the list of elements and not excluding any combinations ofelements in the list of elements. This definition also allows thatelements may optionally be present other than the elements specificallyidentified within the list of elements to which the phrase “at leastone” refers, whether related or unrelated to those elements specificallyidentified. Thus, as a non-limiting example, “at least one of A and B”(or, equivalently, “at least one of A or B,” or, equivalently “at leastone of A and/or B”) can refer, in one embodiment, to at least one,optionally including more than one, A, with no B present (and optionallyincluding elements other than B); in another embodiment, to at leastone, optionally including more than one, B, with no A present (andoptionally including elements other than A); in yet another embodiment,to at least one, optionally including more than one, A, and at leastone, optionally including more than one, B (and optionally includingother elements). The phrases “at least one”, “one or more”, and “and/or”are open-ended expressions that are both conjunctive and disjunctive inoperation. For example, each of the expressions “at least one of A, Band C”, “at least one of A, B, or C”, “one or more of A, B, and C”, “oneor more of A, B, or C” and “A, B, and/or C” means A alone, B alone, Calone, A and B together, A and C together, B and C together, or A, B andC together.

Based on: “Based on” does not mean “based only on”, unless expresslyspecified otherwise. In other words, the phrase “based on” describesboth “based only on,” “based at least on,” and “based at least in parton.”

Comprising: In the claims, as well as in the specification, alltransitional phrases such as “comprising,” “including,” “carrying,”“having,” “containing,” “involving,” “holding,” “composed of,” and thelike are to be understood to be open-ended, i.e., to mean including butnot limited to. Only the transitional phrases “consisting of” and“consisting essentially of” shall be closed or semi-closed transitionalphrases, respectively, as set forth in the United States Patent OfficeManual of Patent Examining Procedures, Section 2111.03.

Determining: “Determining” encompasses a wide variety of actions andtherefore “determining” can include calculating, computing, processing,deriving, investigating, looking up (e.g., looking up in a table, adatabase or another data structure), ascertaining and the like. Also,“determining” can include receiving (e.g., receiving information),accessing (e.g., accessing data in a memory) and the like. Also,“determining” can include resolving, selecting, choosing, establishingand the like.

Embodiments: Reference throughout the specification to “one embodiment,”“an embodiment,” “some embodiments,” “one aspect,” “an aspect,” “someaspects,” “some implementations,” “one implementation,” “animplementation,” or similar construction means that a particularcomponent, feature, structure, method, or characteristic described inconnection with the embodiment, aspect, or implementation is included inat least one embodiment and/or implementation of the claimed subjectmatter. Thus, the appearance of the phrases “in one embodiment” or “inan embodiment” or “in some embodiments” (or “aspects” or“implementations”) in various places throughout the specification arenot necessarily all referring to the same embodiment and/orimplementation. Furthermore, the particular features, structures,methods, or characteristics may be combined in any suitable manner inone or more embodiments or implementations.

Exemplary: “Exemplary” is used exclusively herein to mean “serving as anexample, instance, or illustration.” Any embodiment described herein as“exemplary” is not necessarily to be construed as preferred oradvantageous over other embodiments.

Flow diagram: Exemplary methods may be better appreciated with referenceto flow diagrams or flow charts. While for purposes of simplicity ofexplanation, the illustrated methods are shown and described as a seriesof blocks, it is to be appreciated that the methods are not limited bythe order of the blocks, as in different embodiments some blocks mayoccur in different orders and/or concurrently with other blocks fromthat shown and described. Moreover, less than all the illustrated blocksmay be required to implement an exemplary method. In some examples,blocks may be combined, may be separated into multiple components, mayemploy additional blocks, and so on. In some examples, blocks may beimplemented in logic. In other examples, processing blocks may representfunctions and/or actions performed by functionally equivalent circuits(e.g., an analog circuit, a digital signal processor circuit, anapplication specific integrated circuit (ASIC)), or other logic device.Blocks may represent executable instructions that cause a computer,processor, and/or logic device to respond, to perform an action(s), tochange states, and/or to make decisions. While the figures illustratevarious actions occurring in serial, it is to be appreciated that insome examples various actions could occur concurrently, substantially inseries, and/or at substantially different points in time. In someexamples, methods may be implemented as processor executableinstructions. Thus, a machine-readable medium may store processorexecutable instructions that if executed by a machine (e.g., processor)cause the machine to perform a method.

May: Note that the word “may” is used throughout this application in apermissive sense (i.e., having the potential to, being able to), not amandatory sense (i.e., must).

Order of steps: It should also be understood that, unless clearlyindicated to the contrary, in any methods claimed herein that includemore than one step or act, the order of the steps or acts of the methodis not necessarily limited to the order in which the steps or acts ofthe method are recited.

As used herein, the term “formation” refers to any definable subsurfaceregion. The formation may contain one or more hydrocarbon-containinglayers, one or more non-hydrocarbon containing layers, an overburden,and/or an underburden of any geologic formation.

As used herein, the term “hydrocarbon” refers to an organic compoundthat includes primarily, if not exclusively, the elements hydrogen andcarbon. Examples of hydrocarbons include any form of natural gas, oil,coal, and bitumen that can be used as a fuel or upgraded into a fuel.

As used herein, the term “hydrocarbon fluids” refers to a hydrocarbon ormixtures of hydrocarbons that are gases or liquids. For example,hydrocarbon fluids may include a hydrocarbon or mixtures of hydrocarbonsthat are gases or liquids at formation conditions, at processingconditions, or at ambient conditions (20° C. and 1 atm pressure).Hydrocarbon fluids may include, for example, oil, natural gas, gascondensates, coal bed methane, shale oil, shale gas, and otherhydrocarbons that are in a gaseous or liquid state.

As used herein, the term “sensor” includes any sensing device or gaugecapable of monitoring or detecting pressure, temperature, fluid flow,vibration, resistivity, or other formation and/or fluid data. The sensormay an electrical sensor, an optical sensor, or any other suitable typeof sensor. Alternatively, the sensor may be a position sensor.

As used herein, the term “subsurface” refers to geologic strataoccurring below the earth's surface.

As used herein, the term “wellbore” refers to a hole in the subsurfacemade by drilling or insertion of a conduit into the subsurface. Awellbore may have a substantially circular cross section, or othercross-sectional shape. As used herein, the term “well,” when referringto an opening in the formation, may be used interchangeably with theterm “wellbore.”

Description

Specific forms will now be described further by way of example. Whilethe following examples demonstrate certain forms of the subject matterdisclosed herein, they are not to be interpreted as limiting the scopethereof, but rather as contributing to a complete description.

According to disclosed aspects, a method is disclosed for determininglocations and flow rates of multiple inflows and/or outflows into or outof a wellbore. The wellbore may be vertical, horizontal, curved,deviated or any combination thereof. One or more sources of heating orcooling are deployed at one or more locations along the wellbore tocreate measurable temperature differences between the flowing wellborefluids and locally modified fluid temperature. With these measuredtemperature differences, it becomes possible to model the heat transferassociated with each downstream inflow or outflow, by location, and totherefore calculate the flow rate of each inflow or outflow. This waspreviously made difficult in horizontal wells since production inflowscome in at approximately the same temperature and injection outflowsexit the well at approximately the same temperature. Temperaturedifferences can be induced at one or more locations or can be initiatedby moving a source along the wellbore.

FIG. 3 depicts a temperature measurement system according to disclosedaspects. The temperature measurement system is shown in thisnon-limiting example as a distributed temperature sensing (DTS) system300. DTS system 300 may be used to measure the temperature in a wellbore110 or for other purposes. A transmitter 102 irradiates a waveguide 120with light signals (pump radiation) capable of causing scattering. Acoupler 104 includes suitable optical elements to guide pump radiationdown the waveguide 120 and guide backscattered light signals to areceiver 106. The receiver 106 translates the backscattered lightsignals into electrical signals that are fed to a processor 108 capableof generating a distributed temperature profile therefrom. FIG. 2illustrates the waveform 202 across a spectrum of backscattered lightsignals generated by the pump radiation. As illustrated, thebackscattered signals include signals in the Stokes and anti-Stokesbands. These signals are typically processed by the processor 108 at thesurface to calculate a ratio of the magnitude of backscattered lightintensity between upper and lower frequency bands of detected signals.There is a known temperature dependence of this ratio, which allows forconvenient temperature sensing based on the detected light signalsscattered to the surface. The anti-Stokes signal is sensitive totemperature changes, which result in changes in amplitude of theanti-Stokes signal (as illustrated by the dashed line 204), while theStokes signal is insensitive to temperature. Because the speed of lightin the waveguide 120 is known, it is possible to determine positionsalong the fiber at which scattering occurred, based on the time ofarrival of the backscattered light signals. Hence, the DTS system iscapable of measuring temperature as a continuous function of positionover a length of the fiber, which may be correlated to a depth of thewellbore.

As previously discussed, most zonal allocation workflows usingtemperature data rely on the difference between the fluid temperatureentering the wellbore from the reservoir at each depth and the(typically warmer) fluid temperature of the fluid already in thewellbore flowing from deeper in the well. By calculating the expectedheat loss as the fluid travels up the well, the expected temperature dueto mixing of the fluids entering the wellbore, and the impact of anyJoule-Thomson heating/cooling of the fluids as they change pressure, itis possible to use detailed temperature measurements to model the zonalinflows along the wellbore. However, this difference in fluid entrytemperature along the length of the wellbore is generally very small inhighly deviated or horizontal wells. As shown in FIG. 3, hydrocarboninflows 302, 304, 306 enter a horizontal portion 308 of the wellbore110. Because the natural geothermal temperature gradient is assumed tobe the same at similar depths, a method relying on depth-basedtemperature differences will not provide reliable flow predictions.

According to aspects of the disclosure, a means for effecting atemperature change is provided in the wellbore. In an aspect, the meansfor effecting a temperature change is a temperature changing element,which is shown here as a heating element 312. As shown in FIG. 3, theheating element 312 generates a pulse of heat that alters the fluidtemperature between flowing zones 302 a, 304 a, 306 a. With asufficiently dense spatial measurement of temperature, such as with aDTS system, the movement of the fluid heated by the heating element canbe tracked over a known distance for a known length of time to calculatethe bulk velocity of the fluid. By repeating this process between eachinflow zone, changes in fluid flow rate due to inflows or outflows offluid in each zone can be computed, to provide zonal allocation in acommingled, highly deviated or horizontal well. In addition to bulkvelocity measurements, the rate of spreading of the temperaturevariation can be analyzed to characterize aspects of the fluid mixturesuch as slip velocity and bulk thermal conductivity.

FIGS. 4A and 4B demonstrate how the disclosed aspects may be used. Inthe case shown therein, the wellbore fluid from the inflow at 5,600meters, normally at 315° F., has been heated by the heating element to330° F., enabling clear delineation and modelling of the subsequent fourzones downstream as compared to the case where no heater is used. Thiswell is producing 1,000 barrels oil per day total, shown here with theheating element placed in the portion where 100 bpd are upstream of theheat. FIG. 4C demonstrates that, based on the sensed temperatures, flowrates from hydrocarbon inflows (such as those shown in FIG. 3) may bepredicted.

According to the disclosed aspects, a system and method is provided toeffect a temperature change in a wellbore fluid, which serves to add orremove thermal energy from a producing or injecting oil and/or gasand/or water well, to enable the accurate identification of the amountand flow direction of fluids being produced or injected to each ofseveral zones connected to the well. As previously discussed, thisthermal energy may be provided by one or more heat sources or coolinglocations, thereby providing continuous or pulsed thermal influence,enabling nearly steady-state or transient thermal analysis of the heatflow, such that the fluid flow direction and cumulative ratecontribution can be quantitatively determined at each point of interest.Measurements acquired by this system and method include temperature atseveral points along the well. Pressure measurements and/or fluid flowmeasurements at one or more points may also be acquired. The use of aforward numerical model of wellbore thermal and hydraulic flowingconditions, including frictional pressure effects, hydrostatic pressureeffects, multiphase compositional modeling of the fluid as it undergoespressure and temperature changes, and the effects of piping andequipment including valves, screens, chokes and similar downholeequipment and modeling of the thermal sources/sinks imparted by thetool, allows the generation of a simulated heat flow profile, using asteady-state thermal analysis or a transient thermal analysis, along atleast a portion of the wellbore. The simulated heat flow profile may becompared to the measured temperature of the fluid at several pointsalong the wellbore. The results of this comparison may be fed as inputsto an inversion model which solves the inverse problem of allocatingfluid flow or injection to each wellbore zone contributing to the totalfluid flow rate measured at the surface. The can be repeated until thetemperatures predicted by the inversion model correspond as closely aspossible to the measured temperatures in the wellbore.

The system and method disclosed herein may determine fluid velocity atseveral points by time-of-flight calculations of dispersion of thethermal pulse up or down the well. The disclosed aspects may be usedwith any system for distributed temperature measurement, such as the DTSsystem as disclosed herein. Other temperature sensing systems mayinclude a series of thermocouples or other sensors may be arranged atvarious locations throughout the wellbore. For example, the sensors maybe positioned outside the casing in cemented and/or uncemented casingsegments. The sensors may be positioned outside of tubing strings thatare inside the well casing. Alternatively or additionally, the sensorsmay be positioned inside capillary tubes installed inside the well. Suchcapillary tubes may be pumped down or mechanically tractored into thewell. In another aspect, temperatures may be sensed using a plurality offiber Bragg gratings etched on a length of an optical fiber. In thisinstance, the optical fiber expands or contracts slightly as a functionof temperature, and a precise temperature therefore may be measured bysensing positional changes in the etched gratings due to thetemperature-induced strain. Other suitable temperature sensing systemsmay be used.

The means of effecting a temperature change has been described herein asbeing a temperature modifying element such as a heating element. Theheating element may be electrically powered. Alternatively, the meansfor effecting a temperature change may be a radiation source thatgenerates heat through the principles of nuclear decay. In anotheraspect, an exothermic or endothermic chemical reaction may be used toeffect the temperature change. In a non-limiting example, one or morechemically reactive fluids or solids or may be separately transportedthrough a tube in the wellbore and permitted to react with one anotherat a desired location, thereby creating a source of heat or cold. Instill another aspect, a piezoelectric element may be employed to reducethe temperature at a location according to known principles. In stillanother example, a heated or cooled fluid may be pumped to a desiredlocation in the wellbore and permitted to combine with other fluidsflowing therein. Other means of effecting a temperature change mayalternatively be used in accordance with disclosed aspects. The meansfor effecting the temperature change may operate in a continuous manneror in a pulsed manner.

It is possible that the temperature boost created by a single means foreffecting a temperature change decays too quickly to be measured by adesired number of temperature sensors. Likewise, it is possible that asingle means for effecting a temperature change cannot increase thetemperature sufficient to be accurately measured. According to thedisclosure, more than one means for effecting a temperature change maybe employed at the same or at different locations in the wellbore. Themeans so employed may be of the same type (i.e., two electronic heatingelements) or may differ (i.e., a piezoelectric element and anendothermic chemical reaction). The plurality of means may therebyprovide sufficient temperature differentiation for the discretetemperature measurement points as disclosed herein.

The disclosed aspects may also be used with fiber optic distributedpressure measurements. The disclosed aspects may be used with severaldiscrete pressure sensors and/or fluid flow sensors. The means foreffecting a temperature change may be deployed in a wellbore using rods,a continuous rod, a hollow continuous rod, drill pipe, or tubing. It mayalternatively be deployed with coiled tubing, or with wireline or atractored wireline. Lastly, the means of effecting the temperaturechange and associated sensors may be used in conjunction with variouscomputational, communications, and/or storage technologies.

FIG. 5 is a flowchart showing a method 500 of determining movement of afluid into or out of a subsurface wellbore. This method enables accurateallocation of fluids being produced by or injected into each of severalzones of the wellbore. At block 502 a temperature change is effected inthe fluid at a first location in the wellbore. The temperature changemay be effected by, for example, an electric heating element. At block504 a temperature of the fluid is measured at one or more sensinglocations downstream of the location of the temperature change. A changein temperature between the first location and each of the one or moresensing locations is representative of heat flow within the wellbore. Atblock 506 a simulated heat flow profile is generated from a wellboremodel. At block 508 the simulated heat flow profile is compared to themeasured temperature of the fluid at the one or more sensing locations.At block 510 an inversion model is used to determine, for a plurality ofpoints of interest, a fluid flow direction and/or a cumulative flow ratecontribution.

One or more steps of the disclosed aspects may be accomplished using acomputing device. For example, a computing device is particularly suitedfor automating the repetitive actions required to generate a simulatedheat flow model and to an inversion model. One of ordinary skill in theart will readily understand how to employ a computing device toaccomplish various aspects of the disclosure.

Further illustrative, non-exclusive examples of systems and methodsaccording to the present disclosure are presented in the followingenumerated paragraphs. It is within the scope of the present disclosurethat an individual step of a method recited herein, including in thefollowing enumerated paragraphs, may additionally or alternatively bereferred to as a “step for” performing the recited action.

1. A method of determining movement of a fluid into or out of asubsurface wellbore, to thereby enable accurate allocation of fluidsbeing produced by or injected into each of several zones of thewellbore, comprising:

effecting a temperature change in the fluid at a first location in thewellbore;

measuring a temperature of the fluid at one or more sensing locationsdownstream of the location of the temperature change, wherein a changein temperature between the first location and each of the one or moresensing locations is representative of heat flow within the wellbore;

generating a simulated heat flow profile from a wellbore model;

comparing the simulated heat flow profile to the measured temperature ofthe fluid at the one or more sensing locations; and

using an inversion model, determining, for a plurality of points ofinterest, a fluid flow direction and/or a cumulative flow ratecontribution.

2. The method of paragraph 1, wherein the first location is a singlelocation in the wellbore.

3. The method of paragraph 1 or paragraph 2, wherein the temperature issensed using a distributed temperature sensing system (DTS).

4. The method of paragraph 1 or paragraph 2, wherein the temperature issensed using one or more thermocouples, and wherein at least onethermocouple is disposed at each of the plurality of sensing locations.

5. The method of paragraph 1 or paragraph 2, wherein the temperature issensed using a plurality of gratings on an optical fiber inserted intothe wellbore, and wherein at least one of the plurality of gratings aredisposed at each of the plurality of sensing locations.6. The method of any one of paragraphs 1-5, further comprising using atemperature modifying element to effect the temperature change.7. The method of paragraph 6, wherein the temperature modifying elementis selected from one or more of the following: an electrically poweredheating element, a radiation source, or a piezoelectric element.8. The method of any one of paragraphs 1-5, wherein the temperaturechange is effected by pumping a heating fluid or a cooling fluid to thefirst location.9. The method of any one of paragraphs 1-5, wherein the temperaturechange is effected by an exothermic chemical reaction or an endothermicchemical reaction at the first location.10. The method of any one of paragraphs 1-9, wherein the temperature iseffected in at least one of a continuous manner and a pulsed manner.11. The method of any one of paragraphs 1-10, wherein the heat flowprofile is generated using a steady-state or a transient thermalanalysis of the heat flow.12. The method of any one of paragraphs 1-11, further comprising:

measuring a pressure of the fluid at one or more pressure sensinglocations downstream of the location of the temperature change;

generating a simulated pressure profile from the wellbore model;

comparing the simulated pressure profile to the measured pressure of thefluid at the one or more pressure sensing locations; and

using the inversion model, determining, for a second plurality of pointsof interest, a fluid flow direction and/or a cumulative flow ratecontribution.

13. The method of any one of paragraphs 1-12, further comprising:

measuring a flow rate of the fluid at one or more flow rate sensinglocations downstream of the location of the temperature change;

generating a simulated fluid flow rate profile from the wellbore model;

comparing the simulated fluid flow rate profile to the measured flowrate of the fluid at the one or more fluid flow rate sensing locations;and

using the inversion model, determining, for a second plurality of pointsof interest, a fluid flow direction and/or a cumulative flow ratecontribution.

14. The method of any one of paragraphs 1-13, wherein the wellbore modelis a forward model.

15. The method of any one of paragraphs 1-14, further comprising:

deploying the means of effecting the temperature change using one ormore of a continuous rod, a plurality of rods, a hollow continuous rod,drill pipe, tubing, coiled tubing, wireline, or a tractored wireline.

16. A system for determining movement of a fluid into or out of asubsurface wellbore, to thereby enable accurate allocation of fluidsbeing produced by or injected into each of several zones of the well,comprising:

means for effecting a temperature change in the fluid at a firstlocation in the wellbore;

means for measuring a temperature of the fluid at one or more sensinglocations downstream of the location of the temperature change, whereina change in temperature between the first location and each of the oneor more sensing locations is representative of heat flow within thewellbore;

means for generating a simulated heat flow profile from a wellboremodel;

means for comparing the simulated heat flow profile to the measuredtemperature of the fluid at the one or more sensing locations; and

means for using an inversion model to determine, for a plurality ofpoints of interest, a fluid flow direction and/or a cumulative flow ratecontribution.

17. The system of paragraph 16, wherein the means for effecting atemperature change is a temperature modifying element.

18. The system of paragraph 17, wherein the temperature modifyingelement comprises at least one of an electrically powered heatingelement, a radiation source, or a piezoelectric element.

19. The system of paragraph 16, wherein the means for effecting atemperature change comprises a heating fluid or a cooling fluid that ispumped to the location in the wellbore.

20. The system of paragraph 16, wherein the means for effecting atemperature change is an exothermic chemical reaction or an endothermicchemical reaction at the first location.

INDUSTRIAL APPLICABILITY

The apparatus and methods disclosed herein are applicable to the oil andgas industry.

It is believed that the disclosure set forth above encompasses multipledistinct inventions with independent utility. While each of theseinventions has been disclosed in its preferred form, the specificembodiments thereof as disclosed and illustrated herein are not to beconsidered in a limiting sense as numerous variations are possible. Thesubject matter of the inventions includes all novel and non-obviouscombinations and subcombinations of the various elements, features,functions and/or properties disclosed herein. Similarly, where theclaims recite “a” or “a first” element or the equivalent thereof, suchclaims should be understood to include incorporation of one or more suchelements, neither requiring nor excluding two or more such elements.

It is believed that the following claims particularly point out certaincombinations and subcombinations that are directed to one of thedisclosed inventions and are novel and non-obvious. Inventions embodiedin other combinations and subcombinations of features, functions,elements and/or properties may be claimed through amendment of thepresent claims or presentation of new claims in this or a relatedapplication. Such amended or new claims, whether they are directed to adifferent invention or directed to the same invention, whetherdifferent, broader, narrower, or equal in scope to the original claims,are also regarded as included within the subject matter of theinventions of the present disclosure.

While the present invention has been described and illustrated byreference to particular embodiments, those of ordinary skill in the artwill appreciate that the invention lends itself to variations notnecessarily illustrated herein. For this reason, then, reference shouldbe made solely to the appended claims for purposes of determining thetrue scope of the present invention.

What we claim:
 1. A method of determining movement of a fluid into orout of a subsurface wellbore, to thereby enable accurate allocation offluids being produced by or injected into each of several zones of thewellbore, comprising: effecting a temperature change in the fluid at afirst location in the wellbore; measuring a temperature of the fluid atone or more sensing locations downstream of the location of thetemperature change, wherein a change in temperature between the firstlocation and each of the one or more sensing locations is representativeof heat flow within the wellbore; generating a simulated heat flowprofile from a wellbore model; comparing the simulated heat flow profileto the measured temperature of the fluid at the one or more sensinglocations; using an inversion model, determining, for a plurality ofpoints of interest, a fluid flow direction and/or a cumulative flow ratecontribution; and wherein the method further comprises: measuring apressure of the fluid at one or more pressure sensing locationsdownstream of the location of the temperature change; generating asimulated pressure profile from the wellbore model; comparing thesimulated pressure profile to the measured pressure of the fluid at theone or more pressure sensing locations; and using the inversion model,determining, for a second plurality of points of interest, a fluid flowdirection and/or a cumulative flow rate contribution.
 2. The method ofclaim 1, wherein the first location is a single location in thewellbore.
 3. The method of claim 1, wherein the temperature is sensedusing a distributed temperature sensing system (DTS).
 4. The method ofclaim 1, wherein the temperature is sensed using one or morethermocouples, and wherein at least one thermocouple is disposed at eachof the plurality of sensing locations.
 5. The method of claim 1, whereinthe temperature is sensed using a plurality of gratings on an opticalfiber inserted into the wellbore, and wherein at least one of theplurality of gratings are disposed at each of the plurality of sensinglocations.
 6. The method of claim 1, further comprising using atemperature modifying element to effect the temperature change.
 7. Themethod of claim 6, wherein the temperature modifying element is selectedfrom one or more of the following: an electrically powered heatingelement, a radiation source, or a piezoelectric element.
 8. The methodof claim 1, wherein the temperature change is effected by pumping aheating fluid or a cooling fluid to the first location.
 9. The method ofclaim 1, wherein the temperature change is effected by an exothermicchemical reaction or an endothermic chemical reaction at the firstlocation.
 10. The method of claim 1, wherein the temperature is effectedin at least one of a continuous manner and a pulsed manner.
 11. Themethod of claim 1, wherein the heat flow profile is generated using asteady-state or a transient thermal analysis of the heat flow.
 12. Themethod of claim 1, wherein the wellbore model is a forward model. 13.The method of claim 1, further comprising: deploying the means ofeffecting the temperature change using one or more of a continuous rod,a plurality of rods, a hollow continuous rod, drill pipe, tubing, coiledtubing, wireline, or a tractored wireline.
 14. A method of determiningmovement of a fluid into or out of a subsurface wellbore, to therebyenable accurate allocation of fluids being produced by or injected intoeach of several zones of the wellbore, comprising: effecting atemperature change in the fluid at a first location in the wellbore;measuring a temperature of the fluid at one or more sensing locationsdownstream of the location of the temperature change, wherein a changein temperature between the first location and each of the one or moresensing locations is representative of heat flow within the wellbore;generating a simulated heat flow profile from a wellbore model;comparing the simulated heat flow profile to the measured temperature ofthe fluid at the one or more sensing locations; using an inversionmodel, determining, for a plurality of points of interest, a fluid flowdirection and/or a cumulative flow rate contribution; and wherein themethod further comprises: measuring a flow rate of the fluid at one ormore flow rate sensing locations downstream of the location of thetemperature change; generating a simulated fluid flow rate profile fromthe wellbore model; comparing the simulated fluid flow rate profile tothe measured flow rate of the fluid at the one or more fluid flow ratesensing locations; and using the inversion model, determining, for asecond plurality of points of interest, a fluid flow direction and/or acumulative flow rate contribution.